Viscosified treatment fluids comprising scleroglucan or diutan and associated methods

ABSTRACT

The invention provides a method for treating a subterranean formation penetrated by a wellbore, the method comprising the steps of formulating a treatment fluid and introducing the treatment fluid through the wellbore. The treatment fluid comprises water; diutan; and a sufficient amount of salt to increase the density of the treatment fluid to at least 8.5 lb/gal, wherein at least 50% by weight of the salt is selected from the group consisting of: bromide salts, non-bromide salts having a higher salting-in effect than bromide according to the Hofmeister series as measured by the salt&#39;s effect on the cloud point of poly(ethylene oxide) that has a molecular weight of 4×10 6 , and any combination in any proportion thereof. The invention also provides a treatment fluid for use in a subterranean formation penetrated by a wellbore, the treatment fluid comprising: water; diutan; and a sufficient amount of salt to increase the density of the treatment fluid to at least 8.5 lb/gal, wherein at least 50% by weight of the salt is selected from the group consisting of: bromide salts, non-bromide salts having a higher salting-in effect than bromide according to the Hofmeister series as measured by the salt&#39;s effect on the cloud point of poly(ethylene oxide) that has a molecular weight of 4.10 6 , and any combination in any proportion thereof.

CROSS-REFERENCE TO RELATED APPLICATIONS

This is a continuation of U.S. application Ser. No. 12/543,244 filed onAug. 18, 2009, now U.S. Pat. No. 7,829,508 which is a divisional of U.S.application Ser. No. 11/077,881 filed on Mar. 11, 2005 and issued asU.S. Pat. No. 7,595,282 on Sep. 29, 2009, which is a continuation inpart of U.S. application Ser. No. 10/850,128 filed on May 20, 2004 andnow abandoned, the entire disclosures of which are herein incorporatedby reference.

FIELD OF THE INVENTION

The invention generally relates to methods and compositions for treatinga subterranean formation penetrated by a wellbore. More specifically,the invention relates to compositions and methods for controlling therheology of a diutan-containing well treatment fluid at hightemperatures.

BACKGROUND OF THE INVENTION

A well treatment fluid for use in a subterranean formation penetrated bya wellbore is generally prepared by mixing a base fluid and aviscosifying agent. The base fluid is made up of an aqueous fluid andcan be of any convenient source, including, but not limited to freshwater, seawater, natural brine and formulated brines such as 2% KClsolution. The viscosifying agent thickens or viscosities the base fluidand may assist in the transport of solid particles in the fluid. Atypical viscosifying agent includes or is made from a polysaccharide.

Polysaccharides have been used to alter the viscosity and rheology ofaqueous solutions and are typically used in drilling, completion, andremedial operations. Among other uses, polysaccharides may be used as apart of fracturing gels for hydraulic fracturing, to viscosify drillingfluids, to control fluid loss, as blocking gels, as a part of gravelpacking, frac pack fluids, etc. Heteropolysaccharides, in particular,have been used to alter the viscosity and other rheologicalcharacteristics of aqueous solutions as well as for secondary functions,such as emulsification, suspension of solids, stabilization,flocculation, etc. See, for example, the many applications ofheteropolysaccharides in U.S. Pat. No. 4,326,052 filed Aug. 14, 1990,and U.S. Pat. No. 4,401,760 filed Oct. 21, 1981, both assigned to Merck& Co., Inc, which are hereby incorporated by reference in theirentirety.

However, a treatment fluid can suffer a complete loss of viscosity undercertain conditions to which it may sometimes be subjected in treating asubterranean formation. Examples of such conditions include high shear(caused by the pumping and placement), high temperatures, high pressure,high salinity, and low pH. Under such conditions, the polymeric materialused to viscosify the treatment fluid may degrade rather quickly andlose its viscosifying properties.

In fact, many heteropolysaccharides are ineffective at temperaturesabove 80° C. Xanthan, in particular, is commonly used to viscosifytreatment fluids for applications such as gravel packing, but becomesless effective above 80-90° C.

In order to maintain reservoir fluid control and formation/fluidcompatibility, the density of the fluid may be controlled by addition ofsoluble materials such as salts. These salts can also contribute to lossin viscosity of the treatment fluid.

Accordingly, there is a need for a viscosifying agent that provides highstability in a treatment fluid at elevated temperatures in solutionscontaining electrolytes.

SUMMARY OF THE INVENTION

The invention provides a method for treating a subterranean formationpenetrated by a wellbore, the method comprising the steps of formulatinga treatment fluid and introducing the treatment fluid through thewellbore.

The treatment fluid comprises water; diutan; and a sufficient amount ofsalt to increase the density of the treatment fluid to at least 8.5lb/gal, wherein at least 50% by weight of the salt is selected from thegroup consisting of: bromide salts, nonbromide salts having a highersalting-in effect than bromide according to the Hofmeister series asmeasured by the salt's effect on the cloud point of poly(ethylene oxide)that has a molecular weight of 4×10⁶, and any combination in anyproportion thereof.

The invention also provides a treatment fluid for use in a subterraneanformation penetrated by a wellbore, the treatment fluid comprising:water; diutan; and a sufficient amount of salt to increase the densityof the treatment fluid to at least 8.5 lb/gal, wherein at least 50% byweight of the salt is selected from the group consisting of: bromidesalts, non-bromide salts having a higher salting-in effect than bromideaccording to the Hofmeister series as measured by the salt's effect onthe cloud point of poly(ethylene oxide) that has a molecular weight of4×10⁶, and any combination in any proportion thereof.

These and other aspects of the invention will be apparent to one skilledin the art upon reading the following detailed description. While theinvention is susceptible to various modifications and alternative forms,specific embodiments thereof will be described in detail and shown byway of example. It should be understood, however, that it is notintended to limit the invention to the particular forms disclosed, but,on the contrary, the invention is to cover all modifications andalternatives falling within the spirit and scope of the invention asexpressed in the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying figures together with the description are incorporatedinto and form a part of the specification to illustrate severalprinciples of the present inventions. The figures are only forillustrating the principles of the inventions and are not to beconstrued as limiting the inventions to the illustrated and describedexamples. The various advantages and features of the present inventionswill be apparent from the description of the invention and aconsideration of the drawing in which:

FIG. 1 illustrates a graph of the temperature at which a 0.5% solutionof poly(ethylene oxide), having a molecular weight of 4×10⁶ becomesinsoluble, in concentration of various salts, where salt concentrationis measured in molarity (M).

FIG. 2 illustrates a graph of the elastic modulus of a 0.4% solution ofdiutan in 3M sodium chloride (NaCl);

FIG. 3 illustrates a graph of the elastic modulus of a 0.4% solution ofdiutan in 3M sodium bromide (NaBr);

FIG. 4 illustrates a graph of the elastic modulus of a 0.4% solution ofdiutan in 3M sodium nitrate (NaNO₃);

FIG. 5 illustrates the elastic modulus of a 1% solution of xanthan in 1Msodium chloride (NaCl);

FIG. 6 illustrates the elastic modulus of a 1% solution of xanthan in 1Msodium bromide (NaBr);

FIG. 7 illustrates another technique for showing the difference inbehavior of diutan in potassium chloride (KCl) versus sodium bromide bythe extent of blockage of diutan and salt solutions when pumped throughrock cores at 110° C.; and

FIG. 8 illustrates, as in FIG. 7, a technique for showing the differencein behavior of diutan in sodium chloride versus potassium bromide by theextent of blockage of diutan and salt solutions when pumped through rockcores at 110° C.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The invention provides a method for treating a subterranean formationpenetrated by a wellbore. The treatment fluid of the invention relatesto aqueous wellbore treatment fluids. The water used for the treatmentfluid can be of any convenient or desired source, such as fresh water,seawater, natural brine, formulated brines, and any combination in anyproportion thereof. Formulated brine is manufactured by dissolving oneor more soluble salts in water, natural brine, or seawater.Representative soluble salts include the chloride, bromide, sulphate,nitrate, acetate or formate salts of potassium, sodium, ammonium,calcium, magnesium and zinc. Considering the principles of theinvention, as explained herein, the treatment fluid preferably includesbromide salts over nitrate, sulphate, formate, and chloride salts.

Diutan is one type of heteropolysaccharide that has improved viscosityretention at elevated temperatures when compared to traditionalpolymeric rheology modifiers such as xanthan. Diutan's thickening,suspending, and stabilizing properties in aqueous fluids makes itespecially useful as suspension systems in gravel packing Referred to asheteropolysaccharide S-657, diutan is prepared by fermentation of astrain of Sphingomonas sp. ATCC 53159. Details on preparing diutan maybe found in U.S. Pat. No. 5,175,278, filed Sep. 4, 1990 by Jerry A.Peik, Suzanna M. Steenbergen, and George T. Veeder, hereby incorporatedby reference in its entirety. Diutan is composed principally ofcarbohydrate, about 12% protein and about 7% (calculated as O-acetyl)acyl groups, the carbohydrate portion containing about 19% glucuronicacid, and the neutral sugars rhamnose and glucose in the approximatemolar ratio of 3:2. Other details on diutan can be found in U.S. Pat.No. 6,620,775, filed Nov. 26, 2001 by Philip E. Winston and John M.Swazey, hereby incorporated by reference in its entirety. Diutan can beobtained from CP Kelco US Inc. (Houston), the commercial name beingGeovis.

The amount of diutan in the treatment fluid is selected to be sufficientto provide a desired rheology. If used in a gravel packing fluid, thetreatment fluid contains diutan in an amount sufficient to providesuspension of particulates such as sand. For example, the amount ofdiutan in the gravel packing fluid can range from about 0.01% to about2.0% by weight and preferably between 0.1% to about 1.0%. Other diutanconcentrations are also contemplated for various subterranean formationapplications.

It has been discovered that the performance of diutan is significantlyaffected by the salt content and, unusually for a polysaccharide, salttype. By careful selection of salts for the diutan-containing treatmentfluid, one can maintain the desirable rheological properties of thetreatment fluid in higher temperatures, especially above 80° C.

A discussion will now follow on the Hofmeister series, which arises fromthe solubility properties of polymers in salt solutions. Turninginitially to FIG. 1, illustrated is a graph of the temperature at whicha 0.5% solution of poly(ethylene oxide) or “PEO”, having a molecularweight 4×10⁶ becomes insoluble in various salts, where saltconcentration is measured in moles of salt per liter. The graph, takenfrom Bailey and Callard, J. Applied Polymer Sci., 1959; vol 1; p. 56,illustrates the “salting-in” and “salting-out” ability of saltsaccording to the Hofmeister series, as measured by their effect on thecloud point of PEO.

The salting-in and salting-out effect depends on the nature of the ions,mainly anions and to a lesser extent, cations, involved. Referring tothe Table 1 below, the most effective salting-out anions progress,increasingly, to the left of the table. The salting-out effect, orability to precipitate PEO, is usually found for proteins andhydrophobic polymers, but not for polysaccharides like xanthan or guar.It is the unexpected salting-in effect of certain salts with diutan thatprovides a new method of controlling the rheology of a diutan-containingtreatment fluid at temperatures above 80° C. With respect to thepotassium salts, for example, the order of decreasing salting-out effectis SO₄ ⁻˜CO₃ ⁻>OH⁻>F⁻>Br⁻>I⁻. Table 1 illustrates the most effectivesalting-in anions progressing, increasingly, to the right of the table.Thus, ‘salting-in’ effect, or ability to solubilize PEO, refers to anincrease in solubility on the addition of salt.

TABLE 1 Effect of Salts on Temperature of Precipitation of PEO in Water← Increasing precipitation, or “salting-out” effect Increasingchaotropic, or “salting-in” effect → Anions: PO₄ ³⁻ > SO₄ ²⁻ > HCOO⁻ >CH₃COO⁻ > Cl⁻ > NO₃ ⁻ > Br⁻ > ClO₄ ⁻ > I⁻ > SCN⁻

As suggested by its name, the “cloud point” is the temperature at whicha 0.5% solution of PEO will become insoluble (indicated by the change ofthe solution from clear to cloudy). In pure water, the temperature atwhich a 0.5% solution of PEO will become insoluble is about 98° C. Onthe addition of various salts, this temperature is lowered. The lowerthe cloud point is for the salt, the less soluble the PEO is in thesolution. The Hofmeister series is well known, and reference can be madeto, for example, Bailey and Callard, J. Applied Polymer Sci., 1959; vol1; p. 56; P. von Hippel and T. Schleich, Structure & Stability ofBiological Macromolecules, Marcel Dekker New York, 1969 Chapter 6; andM. Salomaki et al, Langmuir (2004) 20, 3679.

Preferably, the salts of the Hofmeister series for use in the inventionare selected from the group consisting of bromides; other salts having ahigher salting-in effect than bromide according to the Hofmeister seriesas measured by the salt's effect on the cloud point of poly(ethyleneoxide) that has a molecular weight of 4×10⁶; and any combination in anyproportion thereof. Also within the scope of the invention are anionswith a salting-in effect according to the Hofmeister series such asiodide, thiocyanate and perchlorate, as well as mixtures of the saltswith different anions and/or cations.

The amount of salt in the solution is selected to be sufficient toprovide the desired density in the treatment fluid. In one aspect of theinvention, a sufficient amount of salt is added to the treatment fluidto increase the density of the treatment fluid to at least 8.5 lb/gal,wherein at least 50% by weight of the salt is selected from the groupconsisting of: (i) bromide salts, (ii) non-bromide salts having a highersalting-in effect than bromide according to the Hofmeister series asmeasured by the salt's effect on the cloud point of poly(ethylene oxide)that has a molecular weight of 4×10⁶, and (iii) any combination in anyproportion thereof. Preferably; the salt comprises at least 50% byweight of salt selected from the group consisting of potassium bromide,sodium bromide, ammonium bromide, zinc bromide, and calcium bromide.

Preferably, less than 50% by weight of the salt is selected from saltssuch as nitrates, chlorides, formates, and sulfates, which are more ofthe salting-out salts.

This invention is particularly advantageous in gravel packingapplications. In gravel packing, it is sometimes desirable to be able topump a suspension of sand or other particulate into the wellbore withoutthe components of the suspension blocking the rock formation beingtreated. For this reason, the polymers suitable for suspending sand aretested by being pumped into a permeable rock core, and the pressurerequired for the polymers to be pumped through the permeable rock coreis used as a criterion for the polymer's suitability. A suitable polymeris capable of being pumped through a permeable rock without blockingpores. Such a blockage would cause either the flow rate through thepermeable rock to decline (at constant pressure), or the pressure torise at constant flow rate. As described below, standard tests ofpumping diutan solutions through rock cores show the benefit of certainsalts in preference to others.

To demonstrate the advantage of diutan in higher salting-in salts, therheology of solutions of 0.4% diutan in 3M salts was measured. Anoriginal elastic modulus (indicated as G′ and measured in Pascals “Pa”)was measured at 20° C., and a recovered elastic modulus was measured at20° C. after the test solution has been: gradually heated from 20° C. to120° C. at an overall rate of about 3° C. per minute over a period ofabout 30 minutes, held at 120° C. for about 10 minutes, cooled from 120°C. back down to about 30° C. or 40° C. at an overall rate of about minus3° C. per minute over about 30 minutes, and the held at about 30° C. or40° C. for about 30 minutes, the arrows indicate the heating and coolingcycles.

Turning to FIG. 2, illustrated is a graph of the elastic modulus of a0.4% solution of diutan in 3M sodium chloride. As indicated, a gel wasformed at a temperature of about 100° C. The elastic modulus increasedto about 40 Pa, and decreased to near 0 Pa upon cooling below 100° C. Oncooling to the same temperature in the heating cycle at 30° C., therecovered elastic modulus did not recover to its original elasticmodulus value. Without being limited by theory, it is believed that therecovered elastic modulus did not recover to its original value due tothe polymer forming a precipitate above 100° C. Thus, the diutan polymerformed a gel at the lower temperatures until reaching about 100° C.,when the diutan polymer precipitated, unable to reach the originalelastic modulus when returning to about 30° C., the lower temperaturesin the heating cycle.

Turning now to FIG. 3, illustrated is a graph of the elastic modulus ofa 0.4% solution of diutan in 3M sodium bromide. Although the elasticmodulus decreases with increasing temperature, the recovered elasticmodulus value is recovered to at least the value of the original elasticmodulus on cooling to about 30° C. It is believed that the recoveredelastic modulus is recovered to at least the value of the originalelastic modulus on cooling because the diutan polymer does not form aprecipitate at the higher temperatures.

FIG. 4 illustrates a graph of the elastic modulus of a 0.4% solution ofdiutan in 3M sodium nitrate. Similar to the irreversible behavior of 3Msodium chloride illustrated in FIG. 3, the temperature-irreversiblebehavior of the diutan polymer in 3M sodium nitrate is believed to bedue to the precipitation of the diutan polymer at higher temperatures.

FIG. 5 illustrates the elastic modulus of a 1% solution of xanthan in 1Msodium chloride. On cooling the solution, the recovered elastic modulusvalue is nearly the same value of the original elastic modulus. Thexanthan polymer does not form a precipitate at higher temperatures, thusthe recovered elastic modulus is at nearly the same value as theoriginal elastic modulus on returning to cooler temperatures in theheating cycle. This behavior is contrary to behavior of diutan in sodiumchloride, which is illustrated in FIG. 2. For this reason, the inventionprovides the advantage of selecting salts having higher salting-ineffect for treatment fluids in order to avoid precipitation of thediutan at higher temperatures.

FIG. 6 illustrates the elastic modulus of a solution of xanthan in IMsodium bromide. The recovered elastic modulus value is nearly the samevalue as the original elastic modulus on cooling the solution becausexanthan, like diutan, does not form a precipitate at the highertemperature.

As indicated by the rheological data of FIGS. 2-4, the elastic modulusof diutan is quite dependent on the salt type. In contrast, the elasticmodulus of xanthan in the different salt solutions of sodium chlorideand sodium bromide are shown in FIG. 5 and FIG. 6. In both FIG. 5 andFIG. 6, the moduli are quite reversible, indicating that xanthan behavesno differently in sodium chloride than in sodium bromide, asdistinguished with the diutan results.

In one aspect of the invention, the treatment fluid comprises asufficient amount of salt to increase the density of the treatment fluidto at least 8.5 lb/gal, wherein the salt is selected such that a testsolution for the salt comprising 0.4 weight percent of the diutan in a 3molar solution of the salt in de-ionized water has: i) an originalelastic modulus measured at 20° C., and ii) a recovered elastic modulusmeasured at 20° C. after the test solution has been gradually heatedfrom 20° C. to 120° C. at an overall rate of about 3° C. per minute overa period of about 30 minutes, held at 120° C. for about 10 minutes, andcooled from 120° C. back down to 20° C. at an overall rate of aboutminus 3° C. per minute over about 30 minutes, and then held at 20° C.for about 30 minutes; wherein the recovered elastic modulus is at leasthalf the original elastic modulus. Preferably, the recovered elasticmodulus is about equal or greater than the original elastic modulus.

Turning now to FIG. 7, illustrated is another technique to show thedifference in behavior of diutan in potassium chloride compared tosodium bromide by the extent of blockage of the permeable rock coreswhen diutan and salt solutions are pumped through the cores at 110° C.The pressure is measured from pumping brine followed by diutan (0.36%)(Geovis) solution through rock cores (permeability 700 mD). The diutansolution that was tested was a solution with potassium chloride (9.5lb/gal) salt solution and sodium bromide (9.5 lb/gal) salt solution,tested both at 230° F. Experimentally, a one inch diameter rock core ofbrown sandstone, having a permeability of about 700 milliDarcy (mD), wasinserted into a Hassler sleeve apparatus, so the liquids could be pumpedthrough the core. An overburden pressure of 500 pounds per square inch(psi) was maintained on the Hassler sleeve, and a back pressureregulator was set at 200 psi. The computer controlled pump used forpassing fluids through the core was also set not to exceed 200 psi. Thetemperatures of the sleeve and fluids were controlled. Once the core hadreached the desired temperature (here, 110° C.), the brine was pumpedthrough the core at 2 ml/min until constant pressure across the core wasreached. The treating fluid (here, 0.36% diutan with potassium chlorideat 9.5 lb/gal or sodium bromide at 9.5 lb/gal salt) was then pumpedthrough the core at 1 ml/min in the same direction as the brine untileither 10 pore volumes had passed or the pressure reached 200 psi.

The results show that diutan in the presence of potassium chloride saltsolution blocks the pores, causing the pressure to rise to 200 psi,whereas diutan in sodium bromide salt solution does not block the poresto any significant extent and 10 pore volumes passed through at apressure rising to about 25 psi. The data correlates well with therheological behavior, showing that diutan in concentrated chloridesolution forms a precipitate above about 100° C., whereas diutan staysin solution in concentrated bromide solution. The pressure buildup forthe diutan in sodium bromide solution is not greater than 20 psi; it canbe pumped through the rock core with ease, which is indicated by thesmall pressure increase through the rock core. In contrast, the pressurebuild up for the diutan in potassium chloride solution quickly increasesto pressures significantly above 20 psi. Without being limited bytheory, it is believed that this significant build up in pressure withrespect to the potassium chloride salt solution is due to theprecipitation of diutan, causing the rock core to be plugged up.

Turning now to FIG. 8, illustrated is a technique used in FIG. 7 forshowing the difference in behavior of diutan in sodium chloride saltsolution versus potassium bromide salt solution by the extent ofblockage of diutan and salt solutions when pumped through rock cores at110° C. Specifically, illustrated is a graph of the pressure frompumping brine followed by diutan (0.36%) (Geovis) solution through rockcores (permeability 700 mD); diutan is solubilized in sodium chloride(9.5 lb/gal) salt solution or potassium bromide (9.5 lb/gal) saltsolution at 230° F. FIG. 8 shows similar data to that of FIG. 7, exceptthat the systems used were diutan (0.36%) in potassium bromide andsodium chloride, both at 9.6 lb/gal. The data show that diutan was ableto be pumped through the rock in sodium bromide salt solution but not insodium chloride salt solution. Comparison of FIG. 5 and FIG. 6 showsthat it is the chloride ion that causes the diutan to block the rock,whereas the bromide ion allows the diutan to be pumped.

The polymeric system can be degraded easily once the operation iscomplete. Degradation of treatment fluids containing diutan inapplications such as gravel packing may be facilitated by systemsdescribed in U.S. patent application Ser. No. 10/850,128, PublicationNo. US 200510261138, entitled Viscosified Treatment Fluids ComprisingScleroglucan or Diutan and Associated Methods, filed May 20, 2004,herein incorporated by reference in its entirety.

Treatment fluids, of the invention may be used in a variety of wellapplications. Typical well applications include, but are not limited to,a brine thickener in drilling muds and workover fluids, a viscosifyingagent in hydraulic fracturing, gravel packing and frac packingoperations, cementing, a gel blocking agent in diverting applicationsand in non-petroleum applications such as a clarifier for use inrefining processes. Thus, the treatment fluid can be accompanied by apropping agent that results in the placement of proppants within afracture produced in hydraulic fracturing. The fluid can also be used asa temporary blocking gel, also formed by gelation and crosslinking ofappropriate polysaccharides such as diutan, producing a relativelyimpermeable barrier across the production formation. These gels can alsobe used as diverting agents during stimulation treatments. In thiscapacity, the gels are typically pumped into a formation ahead of astimulation fluid, such as an acid stimulation fluid. These gelsselectively enter the more permeable zones of the formation, where theycreate a relatively impermeable barrier across the more permeable zonesof the formation, thus serving to divert the stimulation fluid into theless permeable portions of the formation.

As mentioned above, the treatment fluids of the invention can be used tothicken fluids for sand suspension. In this capacity, they can be usedwith sand or small gravel, such as in gravel packing fluids. Gravelpacking controls sand migration from unconsolidated or poorlyconsolidated formations through the placement of a gravel pack around aslotted or perforated liner or screen liner inserted at a specificlocation within a perforated wellbore. The “gravel” is usually sand orgravel that excludes the formation sand from entering the wellbore. Ingravel packing, sand is transported downhole in a liquid that contains aviscosifying agent. The liquid is preferably clean (i.e. does notcontain insoluble or gelled material that can plug or damage theformation), and still be capable of suspending sand at a broad range oftemperatures. It should be understood by those skilled in the art thatthe fluids can also contain other conventional additives common to thewell service industry.

The invention can also be useful in diutan applications including, butnot limited to, the food industry, the agricultural industry, and a widevariety of other industrial diutan applications. The invention isadvantageous to these industrial applications because there is a needfor diutan to have the ability to withstand high temperatures in saltsolutions.

After careful consideration of the specific and exemplary embodiments ofthe present invention described herein, a person of ordinary skill inthe art will appreciate that certain modifications, substitutions andother changes may be made without substantially deviating from theprinciples of the present invention. The detailed description isillustrative, the spirit and scope of the invention being limited onlyby the appended Claims.

1. A method of treating a portion of a subterranean formationcomprising: providing a viscosified treatment fluid that comprises agelling agent that comprises diutan; introducing the viscosifiedtreatment fluid into the portion of the subterranean formation; andreducing the viscosity of the viscosified treatment fluid using anencapsulated breaker that comprises a peroxide and a coating material.2. The method of claim 1 wherein the viscosified treatment fluidcomprises gravel.
 3. The method of claim 2 further comprising contactingthe portion of the subterranean formation with the viscosified treatmentfluid so as to place a gravel pack in or near the portion of thesubterranean formation.
 4. The method of claim 1 wherein the coatingmaterial comprises a degradable polymeric material.
 5. The method ofclaim 4 wherein the degradable polymeric material comprises at least onedegradable polymeric material selected from the group consisting of apolysaccharide, a chitin, a chitosan, a protein, an aliphatic polyester,a poly(lactide), a poly(glycolide), a poly(ε-caprolactone), apoly(hydroxybutyrate), a poly(anhydride), an aliphatic polycarbonate, anorthoester, a poly(orthoester), a poly(amino acid), a poly(ethyleneoxide), a polyphosphazene, and any combination thereof.
 6. The method ofclaim 1 wherein the viscosified treatment fluid comprises an activatoror a retarder that is compatible with the breaker.
 7. The method ofclaim 6 wherein the retarder comprises sodium thiosulfate.
 8. The methodof claim 1 further comprising contacting the portion of the subterraneanformation with the viscosified treatment fluid so as to create orenhance at least one fracture in the subterranean formation.
 9. Themethod of claim 1 wherein the breaker reduces the viscosity of theviscosified treatment fluid so as to facilitate the recovery of thefluid at the surface.
 10. The method of claim 1 wherein the peroxide ispresent in an amount of from about 0.1 to about 10 gallons of peroxideper 1000 gallons of the viscosified treatment fluid.
 11. The method ofclaim 1 wherein the viscosified treatment fluid comprises at least onesalt selected from the group consisting of potassium chloride, sodiumbromide, ammonium chloride, cesium formate, potassium formate, sodiumformate, sodium nitrate, calcium bromide, zinc bromide, sodium chloride,and any combination thereof.
 12. The method of claim 1 wherein theviscosified treatment fluid further comprises at least one additiveselected from the group consisting of: a pH control additive, asurfactant, a bactericide, a crosslinker, a fluid loss control additive,and any combination thereof.
 13. The method of claim 1 wherein thebreaker comprises at least one breaker selected from the groupconsisting of tert-butyl hydroperoxide and tert-amyl hydroperoxide. 14.The method of claim 1 wherein the viscosified treatment fluid has adensity of from about 8.4 pounds per gallon to about 20.5 pounds pergallon.
 15. The method of claim 1 wherein the subterranean formation hasa temperature of about 200° F. or higher.
 16. A method of treating aportion of a subterranean formation comprising: providing a viscosifiedtreatment fluid that comprises a gelling agent that comprisesscleroglucan; introducing the viscosified treatment fluid into theportion of the subterranean formation; and reducing the viscosity of theviscosified treatment fluid using an encapsulated breaker that comprisesa peroxide and a coating material.
 17. The method of claim 16 furthercomprising stimulating at least a portion of the subterranean formation.18. A method of producing hydrocarbons from a subterranean formationcomprising: providing a viscosified treatment fluid comprising a gellingagent that comprises diutan or scleroglucan; introducing the viscosifiedtreatment fluid into a portion of the subterranean formation; contactingthe portion of a subterranean formation with the viscosified treatmentfluid; and producing hydrocarbons from the subterranean formation. 19.The method of claim 18 wherein the gelling agent comprises diutan andwherein the subterranean formation has a temperature greater than orequal to 200° F.
 20. A method of claim 18 wherein the viscosifiedtreatment fluid comprises a gelling agent comprising diutan and abreaker that comprises a peroxide.